Sandpiper Sandbagged; Wednesday -- October 1, 2014

Updates

October 16, 2014: as noted below, farmers in Iowa are asking the governor to oppose a crude oil pipeline.

A coalition of environmental groups submitted 2,300 petitions to Gov. Terry Branstad on Tuesday asking him to oppose a crude oil pipeline proposed to cut diagonally across Iowa and affect properties in 17 to 19 counties.

Groups opposing the Texas-based Energy Transfer Partners L.P. proposed 1,100-mile Bakken oil pipeline through four states from North Dakota to Patoka, IL, include Iowa Citizens for Community Improvement, Sierra Club Iowa Chapter, the Women, Food and Agriculture Network, and the Food & Water Watch.

October 7, 2014: Sandpiper pipe stacking up. Looks and "feels" just like the Keystone XL, you know, the one killed by President Obama. The link is to the Park Rapids Enterprise.

October 5, 2014: Sounds just like the Keystone XL at Gascoyne, ND. Park Rapids Enterprise is reporting:

Pipes for the Sandpiper oil pipeline are piling up in northern Hubbard County on a site east of Lake George for the project.

Original Post

For those who have forgotten the reason for posting the Enbridge Sandpiper poll at the sidebar at the right, The Dickinson Press was kind enough to bring us up to date:

Enbridge Energy Inc. on Tuesday said its proposed Sandpiper oil pipeline between western North Dakota and Superior, Wis., won’t be completed until 2017, about a year behind the company’s original estimate.

Again, agricultural lobbyists in Wasington, DC; and farmers in Minnesota, Iowa, and Nebraska only need to visit St Paul if they want to see why agricultural shipments will be delayed this year. And next year. And the year after next....which would be 2017.

The pipeline delay will also mean automakers will also see backlogs in getting their products shipped to the west coast.

For investors in Enbridge, this is great news: CAPEX will be delayed; the company will build up its cash reserve, the same thing we saw with TransCanada after the Keystone XL was killed.

But remember, this is not an investment site. Do not make any investment decisions based on anything you read here or think you may have read here.

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Active rigs:

	10/1/2014	10/01/2013	10/01/2012	10/01/2011	10/01/2010
Active Rigs	190	187	186	201	143

RBN Energy: continuation of the series on CO2-EOR.

Enhanced oil recovery is like CPR and a pacemaker to an oil field on the brink of death. Once-vibrant wells whose production had declined to a trickle can be amazingly revived when “flooded” with large volumes of CO2. With continued injections of CO2, those higher production levels can be maintained for years on end. But CO2-EOR requires CO2—lots of it—and the number of mature oil fields that can benefit from EOR is limited by the amount of CO2 that can be produced and piped to where it’s needed. In today’s blog, we continue our look at the Rodney Dangerfield of crude oil production techniques.

The U.S. Department of Energy (DOE) estimates that well over half of the nation’s known oil resources remain “stranded” underground and will require EOR or other advanced techniques to be recovered for productive use.

As we said in Episode 1, primary recovery of oil from a conventional well (through natural pressure and pumps) typically removes only 10% of a reservoir’s total oil, and secondary recovery (mostly injecting water to displace oil and drive it to a production wellbore) removes another 20 to 40%, leaving as much as 70% of a reservoir’s oil in place. 

EOR—or tertiary recovery by injecting CO2—can un-trap a significant portion of what’s left. But going the CO2-EOR route is not for the faint-hearted. First of all, an oil field owner needs reliable access to large volumes of CO2—not just the natural or industrial source of the CO2, but a pipeline to deliver it to the oil field. The pipeline alone can cost tens or even hundreds of millions of dollars; then there’s the cost of the CO2 itself and the costs of injecting the CO2 (usually with intermittent injections of water), removing any CO2 from the oil produced, and recirculating the CO2 for another go-round. Large CO2 separation units can cost up to $50 million a pop. And CO2-EOR isn’t a sure thing.

It doesn’t work well on every field, and in some places it hardly works at all. As a result of the costs and the risks, most of the CO2-EOR projects out there (there are 110-plus, with more than half of them in Texas) are being undertaken by a relatively short list of companies that specialize in CO2-EOR or view it as an important element of their business. Occidental Petroleum (the king of CO2-EOR in the Permian) and Denbury Resources are two, but there are others.

By the way, it's my "feeling" that secondary recovery through waterflooding won't work in the Bakken.

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Northern Oil & Gas announces increase to the borrowing base under its revolving credit facility agreement: Co announced an increase to the borrowing base under its revolving credit facility agreement with its bank syndicate.

• The syndicate of 13 lenders completed its regular semi-annual redetermination of the borrowing base, resulting in an increase from $500 mln to $550 mln. 

... an increase from $500 mln to $550 mln, in case you missed it the first time.

Meanwhile, Oasis:

Oasis Petroleum Inc.  today announced that the lenders under its revolving credit agreement completed their regular semi-annual redetermination of the borrowing base, resulting in an increase to the borrowing base from $1,750 million to $2,000 million.  However, the Company elected to limit the lenders' aggregate commitment to $1,500 million.  The lenders' aggregate commitment can be increased to the full $2,000 million borrowing base by increasing the commitment of one or more lenders.  Oasis did not add any banks to the bank group.  The next redetermination of the borrowing base is scheduled for April 1, 2015.

I believe $2,000 million is $2 billion, but don't quote me on that.